An important factor for managing the development and production of hydrocarbons from a subsurface formation is the effective porosity of the formation. Existing practices for determining effective porosity include a laboratory comparison of core density to the density of known matrix minerals saturated with a known fluid, with or without crushing or other destructive analysis of the core material to improve the mineralogy characterization; performing a mercury injection test and correlating capillary pressure to pore size; performing nuclear magnetic resonance (NMR)-based porosity measurement of the core; performing acoustic wave propagation-based porosity measurement of the core; and electrical conductivity-based porosity measurements of the core. However, when applied to tight gas formations, such practices can be inaccurate and unreliable due to fundamental assumptions about pore connectedness and in-situ properties of the fluids, which assumptions become more significant and unreliable as the porosity decreases.
Another existing approach, known as rate transient analysis (RTA) or dynamic data analysis (DDA), attempts to address this issue by applying the fundamental flow-pressure relationships to a much larger data set, i.e., the production data. These methods match the production curves (including responses to changing borehole conditions) to type curves for pre-existing reservoir models. While these methods appear to have some success, they unfortunately require a substantial amount of time to collect enough data points.
It should be understood, however, that the specific embodiments given in the drawings and detailed description do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative fours, equivalents, and modifications that are encompassed in the scope of the appended claims.